While humankind has been aware of the existence of natural
gas since ancient times, its industrial use is relatively
recent, with the first natural gas wells drilled in North
America in the 19th century. The first true natural
gas processing plants began operating in Canada at the
beginning of the 20th century, but they produced gas mainly for
local heating and lighting.

Natural gas has become increasingly popular since the 1940s,
and its consumption has grown steadily. Fig. 1
shows increasing gas consumption over the 45 years to 2010.
Natural gas is, and will remain, a vital component of the
global energy supply, helped by its environmental advantage
over other fossil fuels and by growing demand from developing
countries. Numerous factors have contributed to the evolution
of the natural gas industry over time:

The gas value chain

Natural gas is a valuable resource, not only as a clean
fuel for power and heat generation, but also as a key raw
material for the petrochemical and chemical
industries. Once cleaned of its impurities, natural gas can be
separated into its major componentsmethane, ethane and
liquefied petroleum gas (LPG)and used as pipeline gas,
liquefied for export or converted to liquid fuels or synthesis
gas (syngas) for the fertilizer industry, as illustrated in
Fig. 2. Natural gas also is a major source of
ethane and LPG for the production of olefins via steam
cracking.

Fig. 2. The natural
gas value chain.

In this article, we discuss the evolution of gas processing
plants to satisfy ever-growing demand, with a focus on
liquefaction and GTL plants.

Natural gas processing

The first step at the majority of the worlds gas
processing plants is to eliminate impurities and to recover
components heavier than methane. This is done to meet
environmental regulations, to avoid corrosion, to maximize
revenue, and to comply with product specifications. Gas
treatment generally involves a number of steps, as shown in
Fig. 3 and listed below:

Separation of liquids (hydrocarbons and free water)

Acid gas removal (CO2 and/or H2S,
when present)

Removal of other sulfur compounds (e.g., carbonyl sulfide and
mercaptans)

Final dehydration for the removal of water to sub-ppm
level, which makes the gas acceptable for the downstream
cryogenic unit or for export requirements

Mercury (Hg) is removed to protect aluminum-based
equipment often present in cryogenic units, such as cryogenic
heat exchangers; it also may be removed for HSE
considerations when the feed gas Hg level is high

Heavy hydrocarbons (including benzene) are often
separated from the gas since they tend to freeze at the low
temperatures encountered in cryogenic sections

Natural gas liquids (NGLs), such as ethane and/or LPG,
might be extracted to meet product gas specifications
(heating value), or because of their inherent economic
value.

Fig. 3. Process flow
of a typical natural gas
processing plant.

Over the last 100 years, natural gas processing has steadily
evolved due to continual scientific and technical advances in
related fields:

Gas/liquids separation has benefited from more efficient
internals and mass transfer devices that have been developed
with the aid of computational fluid dynamics. The incentive to
produce compact equipment to reduce platform costs in the North
Seas hostile environment, starting in the 1970s, has
provided the gas industry with solutions enabling single-train
sizes of up to 1,350 million standard cubic feet per day
(MMscfd).

Today, CO2 and H2S are commonly
removed with one of the formulated amines that have
largely replaced hot carbonate, MEA and caustic soda, which
were once standard solutions. Formulated MDEAs, possibly mixed
with a physical solvent, enable decreased energy consumption,
improved performance and reduced corrosion through lower output
of heat-stable salts. MDEAs also increase the amount of gas
that can be treated in a single column by allowing higher acid
gas loading in the solvent.

Sulfur recovery continues to rely on the Claus process,
although the application of modern acid gas enrichment and tail
gas treating processes means that recovery rates above 99% can
be attained even with the most challenging feed gases.
Additionally, the dehydration of gas upstream of the cryogenic
units is presently done using zeolitesmolecular sieve
material that has efficiently replaced silica gel and the
glycol systems that were first implemented.

Finally, modern, highly optimized cryogenic fractionation
processes using turboexpanders and compact heat exchangers
allow for the recovery of NGLs, such as ethane and LPG, and the
simultaneous removal of heavy hydrocarbons, including
benzene.

The gas processing industry has developed a number of
improved processes that offer reduced equipment count, improved
efficiency and/or reduced operating cost, therefore making it
possible to produce gas from challenging reservoirs. Such
reservoirs include sour gas fields containing high levels of
acid components, such as those encountered in Russia,
Kazakhstan, the Middle East (H2S and CO2)
or the Far East (CO2); deepwater fields (as found
offshore Brazil, Norway, Russia, Australia, the Middle East,
Africa, etc.); and fields located in the Arctic.

With the unequal distribution of natural gas reserves around
the world, the monetization of some of these resources via
pipeline distribution grids or power generation plants can be
limited or even impossible. This opens the door for the
liquefaction of methane for export as liquefied natural gas
(LNG), or for shipment to plants that convert natural gas into
syngas for methanol, ammonia and urea synthesis. More recently,
the conversion of natural gas into synthetic liquid fuels
(synfuels) in gas-to-liquid (GTL) plants has been
industrialized at a large scale.

Rapid growth in LNG

Natural gas liquefaction dates back to the late 19th century
at an experimental level. LNG technology was developed
alongside helium recovery from natural gas in the early 1920s,
but it took until 1941 before a commercial peakshaving plant
started producing LNG in Cleveland, Ohio for storage in
atmospheric tanks.

The possibility of shipping large quantities of LNG to
distant consumers was demonstrated for the first time in 1959
by the worlds first LNG carrier, the Methane
Pioneer. This event demonstrated that large quantities of
LNG could be transported safely across the ocean, creating a
market opportunity for the large gas reserves discovered in
North Africas Hassi RMel field and in the Cook
Inlet area of Alaska.

The LNG industry is considered to be a young industry since
the first baseload export plants were put into operation only
in the mid-1960s. The worlds first baseload LNG export
plant was the Camel plant in Arzew, Algeria.1 It
started up in September 1964, liquefying natural gas from the
Hassi RMel gas field using a propane-ethylene-methane
cascade-refrigeration process. The train capacity was 400,000
tons per year (tpy) of LNG, with production exported primarily
to France and the UK.

The opening of the Camel plant marked the beginning of the
commercial LNG industry. This facility was followed in 1968 by
the startup of the Kenai LNG plant in Alaska, which exported
product to Japan. It was also based on pure-component cascade
technology, although it used gas turbines for the compressor
drivers.

Motivated by the industrys need for larger production
scales and lower equipment count, mixed-refrigerant (MR)
processes soon dominated the LNG sector. The Single Mixed
Refrigerant (SMR) process was adopted by Esso for the Marsa El
Brega plant in Libya in 1970, and the Tealarc double
mixed-refrigerant process was developed. Meanwhile, Sonatrach
adopted the Dual Pressure SMR Tealarc process for its LNG plant
in Skikda, Algeria in 1972, and the Propane Precooled MR (C3MR)
process was first licensed by Shell Brunei in 1972.

The LNG industry has grown relentlessly since 1964,
undergoing considerable changes. The most prominent of these
changes is the increase in single-train capacity, as
illustrated in Fig. 5. Individual LNG train
capacity was multiplied by a factor of nearly 20 with the 2009
startup of the LNG mega-trains at Ras Laffan, Qatar. These
mega-trainsused for Qatargas Trains 4, 5, 6 and 7 and
RasGas Trains 6 and 7each produce 7.8 million tons per
year (MMtpy) of LNG.

Fig. 5. The evolution
of baseload LNG train
capacity over time.

The continual increase in LNG single-train capacity has been
driven by strong demand, and by the industrys efforts to
reduce specific investment and operating costs and to take
advantage of larger equipment sizes and improvements in
efficiency and technology, including:

New refrigerant cycles

Larger, more efficient refrigerant compressor
drivers

Cooling systems that strike a balance of efficiency,
cost, reliability and environmental
impact

Table 1 depicts key features of baseload
LNG plants developed over the last 50 years. In the early years
of baseload LNG export plants, steam turbines were the drivers
of choice for refrigerant compressors, since large turbines
were previously developed for the power generation industry and
were already widely used in the HPI.

A major breakthrough was achieved in the 1980s with the
adaptation of the large, heavy-duty gas turbines used in power
generation for mechanical drive, a change that introduced new
opportunities for the LNG industry. These heavy-duty gas
turbines allowed for high power output, better overall
efficiency and reduced capital cost by avoiding excessive water
use for steam condensation. At the same time, the use of air
cooling for heat rejection appeared as a viable and
lower-capital-intensive solution for plants with difficult or
no access to seawater cooling, such as the North West Shelf
plant in Australia. This trend was maintained in the 1990s and
afterward with the use of more powerful gas turbines, which has
been a key factor in boosting individual LNG train
capacity.

The first decade of the new millennium saw the introduction
of large electrical motorsa driver solution with high
reliability and good efficiency when power generation is based
on a combined cycle. Even though the capital expenditure for
such a system can appear quite high, it reflects an industrial
vision increasingly focused on reliability and the monitoring of
atmospheric emissions. This configuration for
large-capacity plants has been applied once, in the
Snøhvit LNG plant in Norway.

Of course, the evolution of compressor driver technology is
not the sole focus point of the LNG industrys remarkable
progress. The sector also has benefited from continual
technology improvements in a number of other areas:

Developments in gas processing technologies applicable to
the LNG industry, such as high-performance sour gas
sweetening solvents, and zeolites and adsorbents for gas
contaminant removal to trace levels; these technologies make
compliance with stringent product specifications and
environmental regulations possible

Improvements in the capacity and efficiency of
refrigerant compressors

Progress in metallurgy and the ability to manufacture,
transport and install heavy pieces of equipment, such as the
amine absorbers in
Qatargas Trains 4 and 5; each absorber weighs 1,450 tons, is
7.4 m in diameter, and rises 46 m high (Fig.
6)

Improvements in heat exchanger technologyincluding
large spool-wound exchangers; high-pressure aluminum
plate-fin exchangers of large capacity; and high-flux heat
exchangers involving special tube design, such as the
enhanced tubes, which allow for very low temperature
approaches4

To conclude this overview of the evolution of LNG base-load
plants, it is worth noting that, while energy efficiency has
made significant progress over the past 50 years, this can be
mainly attributed to the better integration of power and heat facilities. Improvements in
equipment and process configuration represent only 30%, as
illustrated in Fig. 7.

Fig. 7. Contributions
to energy efficiency
improvements.

Another interesting feature of LNG baseload plants is that
most of the project costs are dictated by
site-related parameters (e.g., quality of feed gas, climatic
conditions, site topography, extent of marine works, local constructionenvironment, accessibility and
availability of infrastructure, economic and political
conditions, environmental constraints, etc.). The technical
design has no influence on these parameters and can only adapt
to them. Although technology selection does not have
the weight in the total project cost that might be expected, it
remains a key parameter for the operation and efficiency of the
plant.

Same-capacity LNG trains, separated 50 years

Nearly five decades lie between the 1964 construction of the
Camel LNG plant in Algeria and the 2012 startup of the Ningxia
Hanas mid-scale LNG plant in China. Both plants have
approximately 400,000-tpy individual train capacities
(Fig. 8).2

Despite the industrys tendency to design and build
individual liquefaction trains of ever-increasing capacity to
improve plant economics, there is a renewed interest in
small-scale LNG (SSLNG) plants for monetizing small gas
reserves and for supplying isolated communities or areas where
the installation of a natural gas distribution grid is too
costly. China, India and Brazil have implemented or
are planning to install SSLNG plants like the one developed at
Ningxia Hanas.

While the Camel plant was designed to process raw natural
gas from a field and is dedicated to overseas LNG export via
tanker, the Ningxia Hanas plant processes pipeline gas that is
already pretreated for contaminants and NGL recovery. The
facilitys feed gas requires compression prior to
liquefaction, and production is delivered via road tanker.
Thus, besides the similarity in capacity, the processing
schemes and plant features of the Camel and Ningxia Hanas LNG
trains have little in common, as illustrated in Table
2.

This comparison reflects the way the LNG industry has
evolved, driven by the need to minimize equipment count and
processing steps to reduce capital investment while at the same
time obtaining the highest possible efficiency to preserve
resources.

A giant leap from Skikda to Qatargas II

An interesting comparison also can be made between the
Skikda and Qatargas II LNG projects (Fig. 9).
Each one was a pioneering development in its time, but the
plants were built and commissioned 36 years apart.
Table 3 shows a comparison of the two
facilities, which were built in 1972 and 2009,
respectively.

Between the first trains of the Skikda plant and the
mega-trains of Qatargas II, the individual LNG throughput per
train has multiplied by a factor of close to 8, and the overall
plant capacity by a factor of 5, leading to a proportional
increase in terms of construction quantities. However, fuel gas
consumption has been multiplied by only 2.8, reflecting the
significant increase in energy efficiency achieved over the
period.

The overall duration of the construction and commissioning
phases also has been reduced despite the increased workload,
the number of simultaneous construction projects in the Ras
Laffan area, and the more complex configuration of the Qatargas
units due to the presence of H2S and organic sulfur
components in the feed gas. The excellent overall efficiency of
Qatargas II is due to the use of gas turbines and the deep integration of heat and power
systems that recover heat energy from gas turbine exhaust and
also use excess compressor driver output for electric power
generation.

The industrys next challenge: FLNG

In recent years, progress in exploration and subsea
production technologies has enabled the development of LNG
projects that monetize gas reserves located in
difficult-to-reach offshore and deepwater locations. An FPSO
can be used when oil is discovered, but the associated gas
usually must be reinjected because export by pipeline is not
economical.

The concept of floating liquefied natural gas (FLNG) is now
seen as a leading solution to monetize these types of gas
resources. Shell was the first company to invest in FLNG, for
the development of its Prelude field offshore Australia. Today,
practically all major oil and gas companies have launched FLNG
programs. The development of FLNG technology has built on the
combination of expertise gained from large oil ​FPSOs,
the latest developments in liquefaction processes, experience
with production on floating platforms and LNG storage, and
innovation in new offloading technologies. Challenges to LNG
development in a marine setting include:

LNG tank sloshing

Offloading LNG between two vessels in the open sea

Importing large quantities of high-pressure feed gas
through a swivel.

The adaptation of large gas processing facilities to marine environments
includes:

Compact designs

Development of equipment for motiona challenge for
large columns and separation equipment

Several FLNG projects are at conceptual or advanced FEED
stages for various locations around the world (Fig.
10). Shells Prelude FLNG (Fig.
11), one of the first FLNG projects, will be operating
200 km offshore Australia.3 Prelude is designed to
produce 3.6 MMtpy of LNG from sulfur-free natural gas, along
with LPGs and C5+ condensate.

Fig. 10. FLNG project
regions and incentives.

Fig. 11. Shell Prelude
FLNG 3D model.

Gas-to-liquids

The Fischer-Tropsch (FT) conversion process is a technology
for the production of long-chain paraffins from a syngas mainly
composed of H2 and CO. The liquid products from FT
conversion can be processed into high-value liquid fuels, lube
oils and specialty waxes. The syngas feeding the FT conversion
unit can be sourced from any carbon-containing primary feed, such
as solid feeds (coal, coke, biomass, etc.), heavy hydrocarbon
liquid residues from oil refineries or natural gas.

While the conversion of coal to motor fuelsor
coal-to-liquids (CTL) productionwas the focus of original
FT technology developments around 80 years ago, the main
interest is now directed toward gas-to-liquids (GTL)i.e.,
the conversion of abundant natural gas resources to
competitively priced, high-quality liquid products.
Fig. 12 depicts the production process for
GTL.

Fig. 12. GTL
production process flow diagram.

It is only in the last 15 years that industry attention has
seriously focused on this monetization route. LNG and GTL are
complementary industries. The interest of major oil and gas
companies in GTL is supported by multiple incentives, as listed
below.

GTL can be an alternative solution to crude oil market
tensions when oil prices are high worldwide, driven by
increasing demand for transportation fuels in developing
economies. Gas is more abundant and, depending on location,
prices are low relative to oil. In particular, the shale gas
revolution in North America promises a durably low-cost feedstock.

Demand for low-sulfur diesel is increasing, and there is
interest in GTL-based kerosine for aviation use. GTL products
are valuable blending components for the diesel and jet fuel
pools, enabling refiners to meet the most stringent
requirements.

Zero-flaring policies are in force in many
countries.

GTL can provide a solution for monetizing stranded gas
reserves.

Infrastructure for the transport and distribution of
liquid fuels is already in place and can be used to market
GTL products.

GTL has benefited from general developments in gas
processing technology that have been driven, to some extent, by
the LNG sector. Specific GTL developments that have contributed
to the technologys strong position include innovation in
reactor and catalyst designs by Sasol and Shell, and the
development of large air separation units and methane reformers
for syngas production.

Proven commercial technologies for the generation of FT
syngas from natural gas are available from applications in the
fertilizer and refining industries:

Steam methane reforming for a high H2:CO ratio
in syngas

Autothermal reforming for an intermediate
H2:CO ratio

Partial oxidation for a low H2:CO ratio.

The optimum solution must be determined on a case-by-case
basis, but the industrys interest is focused on
autothermal reforming and partial oxidation configurations,
with the potential combined use of gas-heated reformer
technology.

GTL technology developments have centered on different FT
reactor concepts (fixed bed, fluidized bed or slurry) and
catalysts (iron or cobalt based). Although several technologies
are at the demonstration-plant stage, only two commercially and
technically proven technologies are in use at large-capacity
plants.

Sasol has strong experience in FT from coal gasification in
South Africa, and it operates two GTL plants: the 23,000-bpd
Mossel Bay GTL refinery in South Africa and the
34,000-bpd Oryx GTL plant (Fig. 13). Oryx GTL,
a joint venture with Qatar Petroleum, was the first GTL plant
in Ras Laffan, Qatar. It was commissioned in 2006.2
This plant processes treated gas produced from neighboring gas
plants in Ras Laffan. Meanwhile, Shell technology has been
applied at the 14,700-bpd Bintulu GTL plant in Malaysia and
also at the 140,000-bpd Pearl GTL plant in Ras Laffan, Qatar.
The Pearl GTL facility, which opened in 2011, is the largest in
the world.

Fig. 13. Oryx GTL plant,
Qatar.

A positive outlook for gas

The use of natural gas on a large scale appeared relatively
late in the 90-year period since Hydrocarbon Processing was first
published.

With high and rapidly increasing proven gas reserves
worldwide, we anticipate that the natural gas industry will
continue to grow and to diversify into markets where usage is
still developing. Gas will represent a larger share of the
energy mix in fast-growing economies such as India and China, and a significantly
bigger share of the transportation fuel market worldwide,
either as LNG or as synthetic liquid fuel.

The technologies needed to shape this transformation exist
and have been proven on a large scale. New innovations that
drive down costs and increase efficiency, while at the same
time adapting to the challenges of harsh offshore and Arctic environments are
needed. HP

ACKNOWLEDGMENT

Technip has a longstanding involvement in this gas value
chain and has been a partner in many first-of-a-kind
developments in gas production and processing. Projects include
oil and gas field development; gas treatment; natural gas
liquids recovery; liquefied natural gas production (both in
onshore and offshore locations); gas-to-liquids production; and
applications for ammonia/urea, hydrogen, ethylene and petrochemical derivatives. Technip,
founded in 1958, has a history that follows a period of gas
industry globalization and intense growth to which the company
contributed many landmark projects.

NOTES

1 Designed and built by Technip2 Built by Technip3 Technip, in collaboration with Samsung is
executing the first FLNG project4 Technip/Wieland enhanced tubes

The authors

Joëlle Castel is the chief
process engineer and technology officer for gas
and sulfur technologies at Technip in Paris, France.
She has more than 35 years of experience in the oil
and gas industry, either as a process manager or as a
technical advisor. Ms. Castel holds degrees in
chemical engineering from Ecole Nationale
Supérieure des Mines, France and IFP School,
France.

Dominique Gadelle is the deputy vice
president of the process and technologies division at
Technip in Paris, France. He has more than 15 years
of experience in the oil and gas industry, and he was
previously in charge of the LNG process engineering
department at Technip in France. He is a member of
the Gas Processors Association and the author of
several papers and presentations. Mr. Gadelle
received a BS in chemical engineering from
Université de Technologie de Compiègne
in France.

Philip Hagyard is the senior vice
president of Technips LNG/GTL product business
unit. Mr. Haygard joined Technip in 1982 and has been
working in the LNG sector for most of his career. He
was the manager of gas and LNG process engineering at
Technip in France during Nigeria LNG, Yemen LNG and
the Qatargas projects. In his current
role, he has helped position Technip for recent
awards in LNG, FLNG and mid-scale LNG. Mr. Haygard is
a chartered chemical engineer in the UK.

Mohamed Ould-Bamba has served as the
vice president of Technips LNG/GTL product
business unit since 2007. He has spent most of his
career in process engineering, covering all aspects
of process design, conceptual studies and detailed
design of the gas value chain. He also has experience
in site activities for gas treatment plants, and he
served as the process manager for Technips EPC
contract for Qatargas II. Mr. Ould-Bamba is a member
of the Gas Processors Association Europe management
committee and is the author of several papers and
presentations. He holds degrees in chemical
engineering from Ecole Nationale Supérieure
des Industries Chimique, France and IFP School,
France.

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Very good TECHNICAL overview and congrats to authors. We didn't read it to support market assumptions/strategy.

Hanne03.13.2013

It is difficult to exegragate the significance of this shift and its consequences for the business model of the big gas suppliers.LOL. It is not difficult for you to exegragate the significance of any bubble Mark. Keep in mind that the shale producers have lost massive amounts of money because their cost of production is much higher than the market prices that are attracting the new investments that you are touting. One side or the other has to be wrong. In all probability both will likely prove to be wrong. Not only will US exports be cheap – they could also be plentiful. How the hell can you export product at a price that is lower than the cost of production? Is this some economic model that you are touting?Eight projects with a total export capacity of 120m tonnes a year have been proposed, according to Wood Mackenzie, a consultancy. If all are approved and built, the US could become one of the world’s biggest LNG producers.Wells cost $5-$10 million to drill. They are depleted within two years. The EUR is too high and the real recovery rate is insufficient to generate a positive cash flow. That makes this one massive bubble just like tech and hosing were. And once again you tend to ignore the reality.

Sudip Kumar Ganguly12.27.2012

An excellent treatise on Gas processing. It is extremely informative and well compiled, my congratulations to all the authors.